Integrated gasification combined cycle (IGCC)

Like PFBC , the technology is relatively new in connection with power generation. Coal-based IGCC plants for power generation passed through a critical stage in their development during the 1990s.

IGCC uses a combined cycle format with a gas turbine driven by the combusted syngas, while the exhaust gases are heat exchanged with water/steam to generate superheated steam to drive a steam turbine. Using IGCC, more of the power comes from the gas turbine. Typically 60-70% of the power comes from the gas turbine with IGCC, compared with about 20% using PFBC.

Coal gasification takes place in the presence of a controlled ‘shortage’ of air/oxygen, thus maintaining reducing conditions. The process is carried out in an enclosed pressurized reactor, and the product is a mixture of CO + H2 (called synthesis gas, syngas or fuel gas). The product gas is cleaned and then burned with either oxygen or air, generating combustion products at high temperature and pressure. The sulphur present mainly forms H2S but there is also a little COS. The H2S can be more readily removed than SO2. Although no NOx is formed during gasification, some is formed when the fuel gas or syngas is subsequently burned.

Three gasifier formats are possible, with fixed beds (not normally used for power generation), fluidized beds and entrained flow. Fixed bed units use only lump coal, fluidized bed units a feed of 3-6 mm size, and entrained flow gasifiers use a pulverised feed, similar to that used in PCC.

IGCC plants can be configured to facilitate CO2 capture. The new gas is quenched and cleaned. The syngas is ‘shifted’ using steam to convert CO to CO2, which is then separated for possible long-term sequestration.


The IGCC demonstration plants use different flow sheets, and will therefore test the practicalities and economics of different degrees of integration. These are discussed in the IEA Coal Research report OECD coal-fired power generation – trends in the 1990s, IEAPER/33. In all IGCC plants, there is a requirement for a series of large heat exchangers, which become major components. In such exchangers, solids deposition, fouling and corrosion may take place. Currently, cooling the syngas to below 100°C is required for conventional cleaning, and it is subsequently reheated before combustion. Substantial heat exchange vessels are needed. At Puertollano, quenching is used to cool the syngas. This is a simple, but relatively inefficient procedure, however, it avoids deposition problems, as the ash present is rapidly cooled to a solid non-sticky form. The cold gas cleaning processes used are variants of well proven natural gas sweetening processes to remove acid impurities and any sulphur present.

Ash behaviour in a gasifier is a critical parameter, both in terms of the satisfactory formation of a slag in entrained flow, and the possibility of solids deposition in the syngas cooler/heat exchanger. At lower temperatures, such as those in fluidized and fixed bed gasifiers, tar formation and deposition may prove to be a difficulty. One advantage of gasification under pressure is that the effective gas volumes involved are far smaller from gasification than from PCC.

There are significant technical challenges. Highly integrated plants tend to have long start-up times (compared to PCC units), and hence may only be suitable for base-load operation.

With pressurized gasification (as with PFBC), the supply of coal into the system is considerably more complex than with PCC. Some gasifiers use bulky and costly lock hopper systems to inject the coal, while others have the coal fed in as a water-based slurry. Similarly, by-product streams have to be depressurized, while heat exchangers and gas cleaning units for the intermediate product syngas must themselves be pressurized.

Some of the major process variations include:

  • the possibility of air separation into oxygen and nitrogen streams prior to the gasification unit;
  • entrained flow units, with a pulverised coal feed, or fluidized bed units with a coarser coal feed and lower operating temperatures (of about 900 versus 1600°C);
  • heat can be recovered from various parts of the system, and used to heat and superheat the steam to be expanded through the steam turbine;
    the syngas is normally cooled to around 50°C in current demonstration units, so that it can be cleaned before being burned and fed to the gas turbine. A better alternative is to treat the syngas in a hot gas cleanup device. These are currently being tested at temperatures of around 500-600°C, so some cooling is still required.

Historically, most gasifiers have been oxygen blown, because of the costs of handling large amounts of nitrogen, and the effect it has in diluting the product syngas. Japanese development, however, is concentrating on air blown systems.

The fundamental advantages of oxygen blown gasification are:

  • reduced gasifier size, and hence cost;
  • the heating value of the cooled and purified syngas is higher;
  • the syngas volume is about half that for an air blown unit for the same amount of coal gasification energy, thus gas handling and cleanup requires smaller units;
  • smaller heat exchangers are required to recover as much of the sensible heat from the syngas as possible before cleanup.

The disadvantage of oxygen blowing is that the degree of plant integration required is considerably increased. This means that controlling and operating the plant is more like running a complex chemical plant than a traditional power station. Matching the requirements for availability, reliability and flexibility of operation (for example, to load follow) at a competitive cost over a long period are the major challenges. Auxiliary power consumption in an air blown system is estimated to be less than 8%, compared with 10-15% for oxygen blown systems. Development in Japan on a 200 t/d pilot scale has been based on the air blown route, and a design has been developed for a commercial size demonstration unit to use 2000 t/d of coal.

The syngas is produced at temperatures up to 1700°C (in entrained flow gasifiers), while the gas clean up systems which are being assessed, operate at a maximum temperature of 600°C. Large heat exchangers are required, and there is the possibility of solids deposition in these exchangers which reduces heat transfer. It seems that unless it is possible to develop hot gas cleaning as a reliable procedure, the comparative economics of IGCC will remain unattractive.

Gasifiers may be able to use coals that would otherwise be difficult to use in PCC plant, such as those with a high sulphur content, or high ash content. The current demonstration units will test various coals, and should resolve many of the technical issues outlined above.

Unit size

A number of demonstration units, mainly around 250 MWe size are being operated in Europe and the USA. Most use entrained flow and are oxygen blown, and one is based on a fluidized bed, and is air-blown. The 235 MWe unit at Buggenum in the Netherlands, started up in 1993. Three plants are in the USA at Wabash River in Indiana; Polk Power near Tampa in Florida and Piñon Pine in Nevada. The largest unit is that at Puertollano in Spain with a capacity of 330 MWe.

All the current coal-fueled demonstration plants are subsidised. The European plants are part of the Thermie programme, and in the US, the DOE is part funding the design and construction, as well as the operating costs for the first few years. Some are repowering projects, but from the point of view of demonstrating the viability of various systems, they are effectively new plant, even though tied to an existing steam turbine.

As gasifiers are pressure vessels, they cannot be fabricated on site in the same way that PCC boilers can. Large gasifiers are difficult to transport, simply because of their weight and sheer size, and this may prove to restrict their eventual use for sizes much above 300 MWe.

Thermal efficiency

As with PFBC, the driving force behind the development is to achieve high thermal efficiencies together with low levels of emissions. With all power generation routes, it is important to assess and compare thermal efficiencies under normal load following conditions, and not just when the unit is operating under full load. It is hoped to reach efficiencies of over 40%, and possibly as high as 45% with IGCC. Higher efficiencies are possible when high gas inlet temperatures to the gas turbine can be achieved. At the moment, the gas cleaning stages for particulates and sulphur removal can only be carried out at relatively low temperatures, which restricts the overall efficiency obtainable.

The main incentive for IGCC development has been that units may be able to achieve higher thermal efficiencies than PCC plant, and be able to match the environmental performance of gas-fired plants. During the development phase, the thermal efficiencies of new PCC plants using superheated steam have also increased.


The emissions of particulates, NOx and SO2 from IGCC units is expected to meet, and possibly to better, all current standards. On most units, sulphur is produced in elemental form as a by-product.


Residues may include both ash and slag, depending on the gasification system used.